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Tuktu Resources Ltd. — Management Reports 2026
Apr 23, 2026
44385_rns_2026-04-23_eed15f6d-311d-4992-aebf-965c82714794.pdf
Management Reports
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Tuktu Resources Ltd.
Management's Discussion and Analysis
As at December 31, 2025 and for the three months and year ended December 31, 2025
The following Management's Discussion and Analysis (the "MD&A") of financial results has been prepared by the management of Tuktu Resources Ltd. ("Tuktu" or the "Company") as at December 31, 2025 and for the three months and years ended December 31, 2025 and 2024 should be read in conjunction with the audited financial statements for the years ended December 31, 2024 and 2023 (the "Financial Statements") and related notes thereto. The date of this MD&A is April 23, 2026.
The financial data presented has been prepared by management in accordance with IFRS Accounting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") and in accordance with the requirements of National Instrument 51-102 – Continuous Disclosure Requirements. The reporting currency in the Interim Financial Statements and in this MD&A is Canadian dollars, unless otherwise stated. Additional information relating to the Company is available on the Company's website at www.tukturesources.com and on the Company's SEDAR+ profile at www.sedarplus.ca.
Description of the Company
Tuktu is a publicly traded company incorporated on November 28, 1994, in the Province of Alberta. The common shares in the capital of Tuktu (the "Common Shares") are listed on the TSX Venture Exchange (the "TSXV") under the symbol "TUK". The Company is in the business of oil and natural gas exploration, development and production. The Company's head office is located at 1750, 444 – 5th Avenue S.W., Calgary, Alberta T2P 2T8, and its registered office is located at 4200 Bankers Hall West, 888 – 3rd Street S.W., Calgary, Alberta T2P 5C5.
Going Concern
The financial statements have been prepared on a going concern basis, which assumes the realization of assets and discharge of liabilities in the normal course of business as they become due. At December 31, 2025, the Company has an accumulated deficit of $28.4 million since inception (December 31, 2024 - $21.3 million). For the year ended December 31, 2025, the Company reported a net loss of $7.1 million (December 31, 2024 - $2.7 million net loss) and cash used in operating activities of $0.2 million (December 31, 2024 - $1.7 million). The Company's working capital balance has decreased from $7.8 million as at December 31, 2024 to $0.4 million as at December 31, 2025.
The Company's ability to continue as a going concern is dependent upon its existing working capital being sufficient to sustain operating activities while the Company attempts to generate positive cash flows from operations, secure funding from debt or equity financings or make other arrangements which may not be available. There can be no assurance one or more of the alternatives will be successful.
These conditions indicate a material uncertainty that may cast significant doubt as to the Company's ability to meet its obligations as they come due and, accordingly, the appropriateness of the use of accounting principles applicable to a going concern. These financial statements do not reflect the adjustments to the carrying amounts of assets and liabilities, reported amounts of expenses, and statement of financial position classifications used that would be necessary were the going concern assumption deemed to be inappropriate. Such adjustments could be material.
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Financial and Operational Highlights
| ($, except share #’s) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Financial Highlights | ||||||
| Petroleum and natural gas sales | 1,610,229 | 2,438,647 | (34)% | 9,018,231 | 6,104,874 | 48% |
| Cash flow used in operating activities | (779,844) | (361,910) | 115% | (153,383) | (1,750,212) | (91)% |
| Per share - basic | (0.00) | (0.00) | 0% | (0.00) | (0.01) | 0% |
| Per share - diluted | (0.00) | (0.00) | 0% | (0.00) | (0.01) | 0% |
| Adjusted funds flow from (used in) operations (1) | (288,773) | 281,500 | 203% | (1,033,395) | (1,021,772) | 1% |
| Per share - basic | (0.00) | 0.00 | 0% | (0.00) | (0.01) | 0% |
| Per share - diluted | (0.00) | 0.00 | 0% | (0.00) | (0.01) | 0% |
| Net income (loss) | (4,952,844) | 396,709 | (1,348)% | (7,084,707) | (2,659,562) | 166% |
| Per share - basic | (0.02) | 0.00 | (100)% | (0.03) | (0.02) | 46% |
| Per share - diluted | (0.02) | 0.00 | (100)% | (0.03) | (0.02) | 46% |
| Total capital expenditures (1) | 222,011 | 343,640 | (35)% | 6,937,106 | 2,204,568 | 215% |
| Adjusted working capital (1) | 853,842 | 8,831,092 | (90)% | 853,842 | 8,831,092 | (90)% |
| Number of common shares outstanding | ||||||
| Common shares outstanding, end of period | 265,563,547 | 259,813,919 | 2% | 265,563,547 | 259,813,919 | 2% |
| Weighted average outstanding - basic | 265,563,547 | 196,738,030 | 35% | 264,913,811 | 145,162,939 | 82% |
| Weighted average outstanding - diluted | 265,563,547 | 259,181,423 | 2% | 264,913,811 | 145,162,939 | 82% |
(1) See Non-IFRS Measures, Non-IFRS Financial Ratios and Capital Management Measures
| Three months ended, December 31, | Year ended, December 31, | |||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Operating Highlights | ||||||
| Average production volumes | ||||||
| Crude oil (bbls/d) | 187 | 271 | (31)% | 264 | 156 | 69% |
| Natural gas (mcf/d) | 1,742 | 2,236 | (22)% | 1,792 | 2,102 | (15)% |
| Total (boe/d) | 477 | 644 | (26)% | 563 | 506 | 11% |
| % natural gas | 61% | 58% | 5% | 53% | 69% | (23)% |
| Average realized prices | ||||||
| Crude oil ($/bbl) | 71.13 | 85.14 | (16)% | 80.72 | 85.85 | (6)% |
| Natural gas ($/mcf) | 2.41 | 1.54 | 57% | 1.90 | 1.56 | 21% |
| Petroleum and natural gas sales ($/boe) | 36.67 | 41.18 | (11)% | 43.91 | 32.94 | 33% |
| Operating netback ($/boe) | ||||||
| Petroleum and natural gas sales | 36.67 | 41.18 | (11)% | 43.91 | 32.94 | 33% |
| Royalties | (7.44) | (9.40) | (21)% | (12.12) | (7.92) | 53% |
| Operating expenses | (23.53) | (16.93) | 39% | (23.27) | (15.10) | 54% |
| Transportation expenses | (0.80) | (1.83) | (56)% | (0.91) | (1.23) | (26)% |
| Operating netback (1) | 4.90 | 13.02 | (62)% | 7.61 | 8.69 | (12)% |
(1) See Non-IFRS Measures, Non-IFRS Financial Ratios and Capital Management Measures
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Production
| (6:1 boe conversion) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Daily production: | ||||||
| Crude oil (bbls/d) | 187 | 271 | (31)% | 264 | 156 | 69% |
| Natural gas (mcf/d) | 1,742 | 2,236 | (22)% | 1,792 | 2,102 | (15)% |
| Total (boe/d) | 477 | 644 | (26)% | 563 | 506 | 11% |
| % Natural gas | 61% | 58% | 5% | 53% | 69% | (23)% |
Fourth quarter ("Q4") 2025 production averaged 477 boe/d (61% natural gas, 39% crude oil), down 26% from 644 boe/d (58% natural gas, 42% crude oil) in Q4 2024. Oil production in Q4 2025 decreased to 187 bbls/d from 271 bbls/d in Q4 2024 due to natural production declines. Natural gas production in Q4 2025 decreased to 1,742 mcf/d from 2,236 mcf/d in Q4 2024 due to production being shut-in during periods when natural gas prices were severely depressed.
For the year ended December 31, 2025, production increased 11% to 563 boe/d (53% natural gas, 47% crude oil) from the comparative period of 2024 due to oil production increasing to 264 bbls/d from 156 bbls/d in the comparable period of 2024. The increase in oil production can be attributed to the production from the Company's light oil discovery well in the southern Alberta Deep Basin. Natural gas production decreased to 1,792 mcf/d from 2,102 mcf/d in the comparable period of 2024 due to production being shut-in during periods when natural gas prices were severely depressed and natural production declines.
Petroleum and Natural Gas Sales
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Crude oil | 1,223,739 | 2,122,677 | (42)% | 7,777,846 | 4,901,814 | 59% |
| Natural gas | 386,490 | 315,970 | 22% | 1,240,385 | 1,203,060 | 3% |
| Total petroleum and natural gas sales | 1,610,229 | 2,438,647 | (34)% | 9,018,231 | 6,104,874 | 48% |
Total petroleum and natural gas sales for the three months ended December 31, 2025, decreased 34% to $1,610,229 as compared to $2,438,647 in the same period of 2024 due to lower production volumes and lower realized oil prices partially offset by higher realized natural gas prices.
For the year ended December 31, 2025, total petroleum and natural gas sales increased 48% to $9,018,231 compared to $6,104,874 in the same period of 2024. The increase is due to higher oil production volumes and realized natural gas prices partially offset by lower natural gas volumes and lower realized oil prices.
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Benchmark and Realized Prices
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Averaged realized prices: | ||||||
| Crude oil ($/bbl) | 71.13 | 85.14 | (16)% | 80.72 | 85.85 | (6)% |
| Natural gas ($/mcf) | 2.41 | 1.54 | 57% | 1.90 | 1.56 | 21% |
| Barrels of oil equivalent ($/boe)(1) | 36.67 | 41.18 | (11)% | 43.91 | 32.94 | 33% |
| Benchmark prices: | ||||||
| WTI ($US/bbl) | 59.14 | 70.27 | (16)% | 64.81 | 76.27 | (15)% |
| Edmonton Light ($/bbl) | 76.39 | 94.91 | (20)% | 85.5 | 97.88 | (13)% |
| AECO natural gas ($/Mcf) | 2.23 | 1.48 | 51% | 1.68 | 1.42 | 18% |
| Exchange rate (US$/C$) | 1.39 | 1.40 | (1)% | 1.40 | 1.37 | 2% |
(1) Disclosure of production on a per boe basis in this MD&A consists of the constituent product types and their respective quantities. Refer to the "BOE Presentation" section of this MD&A
The Company takes most of its working interest production "in kind" which is marketed and sold through various credit-worthy purchasers. The price realized by the Company for natural gas production is determined by the Alberta Energy Company ("AECO") benchmark and based on Canadian fundamentals. The price received by the Company for its oil production is primarily driven by the price of West Texas Intermediate ("WTI"), which is adjusted for quality and a differential.
The AECO natural gas benchmark increased by 51% and 18% in the three months and year ended December 31, 2025, respectively compared to the same periods of 2024. The Company's realized natural gas prices followed a similar trend, increasing 57% and 21% in the three months and year ended December 31, 2025, respectively, compared to the same periods of 2024. The spread between the AECO natural gas benchmark and the Company's realized price is due to natural gas production being shut-in when natural gas prices were severely depressed.
The WTI oil benchmark decreased by 16% and 15% in the three months and year ended December 31, 2025, respectively compared to the same periods of 2024. The Company's realized oil prices experienced declines of 16% and 6% in the three months and year ended December 31, 2025, respectively, compared to the same periods of 2024.
Royalty Expenses
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Royalty expenses | 326,631 | 557,193 | (41)% | 2,488,759 | 1,467,349 | 70% |
| Royalty rate | 20% | 23% | (11)% | 28% | 24% | 15% |
| Per boe ($) | 7.44 | 9.40 | (21)% | 12.12 | 7.92 | 53% |
Royalty expenses consist of crown royalties payable to the Alberta provincial government, freehold mineral rights owners and royalty contract owners. Royalties are calculated based on revenue less allowed costs of transportation and processing and are generally expressed as a percentage of revenue. Royalty rates can vary due to several factors including commodity prices, mix of production subject to each type of royalty, commodity produced, production rate, royalty contract terms, and royalty incentive schemes.
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Royalties for the three months ended December 31, 2025 were $326,631 or a 20% royalty rate as compared to $557,193 or a 23% royalty rate in the same period in 2024. On a royalty rate basis, royalties decreased due to lower oil prices and the declining production on the southern Alberta Deep Basin oil discovery well which attracts a high crown royalty rate due to the high production rates and oil prices.
Royalties for the year ended December 31, 2025 were $2,488,759 or a 28% royalty rate as compared to $1,467,349 or a 24% royalty rate in the same period in 2024. On a royalty rate basis, royalties increased due to the impact of the Alberta Deep Basin oil discovery well noted above.
Operating Expenses
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Operating expenses | 1,032,587 | 1,002,940 | 3% | 4,776,510 | 2,799,227 | 71% |
| Per boe ($) | 23.53 | 16.93 | 39% | 23.27 | 15.10 | 54% |
For the three months ended December 31, 2025, operating expenses increased 3% to $1,032,587 from $1,002,940 in the same period of 2024. The increase was primarily due to $186,048 spent on well workovers in the three months ended December 31, 2025. On a per boe basis, operating expenses for the three months ended December 31, 2025, were $23.53/boe compared to $16.93/boe in the same period of 2024 due to the increase in operating expenses combined with a decline in production.
For the year ended December 31, 2025, operating expenses increased 71% to $4,776,510 from $2,799,227 in the same period of 2024. The increase was due to an increase in higher cost oil production and $1,309,169 spent on well workovers in the year ended December 31, 2025. On a per boe basis, operating expenses for the year ended December 31, 2025, were $23.27/boe compared to $15.10/boe in the same period of 2024.
Transportation Expenses
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Transportation expenses | 35,306 | 108,713 | (68)% | 187,339 | 228,248 | (18)% |
| Per boe ($) | 0.80 | 1.83 | (56)% | 0.91 | 1.23 | (26)% |
Transportation expenses include clean oil trucking and natural gas transportation from the field to the sales point. Transportation costs for the three months ended December 31, 2025 were 68% lower compared to the same period of 2024 due to no clean oil trucking being incurred in 2025 and reduced natural gas transportation due to a decrease in volumes.
For the year ended December 31, 2025, transportation costs decreased 18% from the comparable period of 2024. This is due to lower clean oil trucking costs and lower natural gas transportation costs due to a decrease in volumes.
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Operating Netback
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Total petroleum and natural gas sales | 1,610,229 | 2,438,647 | (34)% | 9,018,231 | 6,104,874 | 48% |
| Royalties | (326,631) | (557,193) | (41)% | (2,488,759) | (1,467,349) | 70% |
| Operating expenses | (1,032,587) | (1,002,940) | 3% | (4,776,510) | (2,799,227) | 71% |
| Transportation expenses | (35,306) | (108,713) | (68)% | (187,339) | (228,248) | (18)% |
| Operating netback(1) | 215,705 | 769,801 | (72)% | 1,565,623 | 1,610,050 | (3)% |
| ($/boe) | Three months ended, December 31, | Year ended, December 31, | ||||
| --- | --- | --- | --- | --- | --- | --- |
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Total petroleum and natural gas sales | 36.67 | 41.18 | (11)% | 43.91 | 32.94 | 33% |
| Royalties | (7.44) | (9.40) | (21)% | (12.12) | (7.92) | 53% |
| Operating expenses | (23.53) | (16.93) | 39% | (23.27) | (15.10) | 54% |
| Transportation expenses | (0.80) | (1.83) | (56)% | (0.91) | (1.23) | (26)% |
| Operating netback(1) | 4.90 | 13.02 | (62)% | 7.61 | 8.69 | (12)% |
(1) See Non-IFRS Measures, Non-IFRS Financial Ratios and Capital Management Measures
For the three months ended December 31, 2025, operating netback was 72% lower than the comparable period of 2024 due to a decline in oil production and realized oil price and an increase in operating costs partially offset by lower royalties and transportation expenses. On a boe basis, operating netback was 62% lower primarily due to lower realized oil pricing and higher operating and transportation expenses partially offset by lower royalties as compared to the same period of 2024.
For the year ended December 31, 2025, operating netback was 3% lower than the comparable period of 2024 due primarily to higher operating expenses and higher royalties this was partially offset by higher petroleum and natural gas sales and lower transportation expenses. On a boe basis, operating netback was 12% lower primarily due to higher operating expenses and royalties and was partially offset by higher realized pricing and lower transportation expenses as compared to the same period of 2024.
General and Administrative ("G&A") Expenses
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| G&A expenses | 524,860 | 579,802 | (9)% | 3,212,201 | 1,766,634 | 82% |
| Capitalized salaries and overhead recoveries | (12,925) | (127,096) | (90)% | (551,820) | (249,226) | 121% |
| Net G&A expenses | 511,935 | 452,706 | 13% | 2,660,381 | 1,517,408 | 75% |
| Per boe ($) | 11.67 | 7.64 | 53% | 12.96 | 8.19 | 58% |
For the three months ended December 31, 2025, net G&A expenses were $511,935 compared to $452,706 in the same period of 2024. The increase in net G&A expenses was due to lower capitalized salaries and overhead recoveries due to the limited amount of capital expenditures. G&A prior to capitalized salaries and overhead recoveries for the three months ended December 31, 2025 were $524,860 compared to $579,802 in the same period of 2024. This is a result of lower salaries due to the executive changes, this was offset by higher professional fees being incurred as a result of the proxy battle initiated by the former
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President and CEO. During the fourth quarter of 2025 $65,312 was incurred with regards to the proxy battle. Net G&A expenses per boe for the three months ended December 31, 2025, were $11.67/boe compared to $7.64/boe in the same period of 2024 due to the increases in G&A expenses mentioned above and the decline in production.
For the year ended December 31, 2025, net G&A expenses were $2,660,381 compared to $1,517,408 in the same period of 2024. The increase in net G&A expenses was a result of estimated executive severance costs and increased professional fees as a result of the proxy battle, consulting fees, directors' fees, head office costs and transfer agent fees partially offset by capitalized G&A related to Tuktu's capital expenditure program. Net G&A expenses per boe for the year ended December 31, 2025, were $12.96/boe compared to $8.19/boe in the same period of 2024 due to increases in G&A expenses mentioned above partially offset by an increase in production.
Share-based Compensation
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Stock options | 50,982 | 51,517 | -1% | 241,416 | 127,019 | 90% |
| Capitalized share-based compensation | - | (17,399) | 100% | (47,046) | (28,961) | 62% |
| Share based compensation | 50,982 | 34,118 | 49% | 194,370 | 98,058 | 98% |
| Per boe ($) | 1.16 | 0.58 | 100% | 0.95 | 0.53 | 79% |
The Company has a stock option plan under which stock options ("Options") to purchase Common Shares of the Company may be granted to directors, officers, employees and consultants. During the three months ended December 31, 2025, the Company recorded gross share-based compensation expense of $50,982 compared to $34,118 in the same period of 2024. The Company capitalizes share-based compensation expense related to petroleum and natural gas exploration and development activities. For the three months ended December 31, 2025, the Company recorded capitalized share-based compensation expense of $nil compared to $17,399 in the comparable period in 2024. The reduction in gross share-based compensation during the three months ended December 31, 2025 compared to same period of 2024 is due to the reduction in outstanding stocks options impacted by the forfeiture of unvested stock options held by executives that were previously severed.
For the year ended December 31, 2025, the Company recorded share-based compensation expense of $194,370 compared to $98,058 in the same period of 2024. During the year ended December 31, 2025, the Company recorded capitalized share-based compensation expense of $47,046, compared to $28,961 in the same periods of 2024 as a result of the increased capital program partially offset by the impact of the forfeiture of stock options mentioned above.
The following table summarizes the Options outstanding and exercisable as at December 31, 2025. The Options that are not exercisable vest as to one-third on each of the first, second and third anniversaries of their grant date, respectively.
| Issued | Number outstanding | Expiry | Exercise price ($) | Exercisable |
|---|---|---|---|---|
| 23-Mar-22 | 1,000,000 | 23-Mar-27 | 0.08 | 1,000,000 |
| 25-Jul-22 | 2,650,000 | 25-Jul-27 | 0.15 | 2,650,000 |
| 13-Dec-22 | 950,000 | 13-Dec-27 | 0.15 | 950,000 |
| 17-Jul-24 | 4,400,000 | 17-Jul-29 | 0.05 | 1,466,667 |
| 03-Dec-24 | 5,200,000 | 03-Dec-29 | 0.09 | 1,733,333 |
| 06-Jan-25 | 220,000 | 06-Jan-30 | 0.10 | - |
| 27-Jan-25 | 200,000 | 27-Jan-30 | 0.14 | - |
| 22-Aug-25 | 240,000 | 22-Aug-30 | 0.05 | - |
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Depletion and Depreciation
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Depletion and depreciation | 490,100 | 616,257 | (20)% | 2,356,627 | 2,390,360 | (1)% |
| Per boe ($) | 11.17 | 10.40 | 7% | 11.48 | 12.89 | (11)% |
Depletion of oil and natural gas assets is calculated using the unit-of-production method which is based on production volumes in relation to the proved plus probable reserves base and the associated future development costs. Depletion and depreciation expenses for the three months and year ended December 31, 2025, were $490,100 and $2,356,627, respectively, compared to $616,257 and $2,390,360 for the same periods of 2024. The decrease for the 3 months ended December 31, 2025 is due to the decline in production.
On a per boe basis, the depletion and depreciation expenses for the three months and year ended December 31, 2025, was $11.17/boe and $11.48/boe, respectively, compared to $10.40/boe and $12.89/boe in the same periods of 2024.
Impairment Expense
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Impairment expense | 4,180,000 | - | 100% | 4,180,000 | - | 100% |
| Per boe ($) | 95.26 | - | 100% | 20.36 | - | 100% |
As at December 31, 2025, indicators of impairment for the Company's Penny CGU were identified due to an unsuccessful drilling program in 2025. As a result, an impairment test was performed. The recoverable amount of the Penny CGU was estimated at fair value less costs to sell. This estimate was based on after-tax discounted cash flows from proved developed producing oil and natural gas reserves.
At December 31, 2025, it was determined that the carrying value of the Penny CGU exceeded its recoverable amount and a $4.18 million impairment was recognized. The before-tax discount rate applied in the calculation was 12%. As at December 31, 2024, there were no indicators of impairment, therefore no impairment test was performed.
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Finance Income and Expense
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Finance income | ||||||
| Interest on short term investments | 10,976 | 32,664 | (66)% | 111,729 | 36,705 | 204% |
| Finance expense | ||||||
| Part XII.6 interest on flow through expenditures under the look-back rule | (3,914) | (4,634) | (16)% | (16,149) | (18,768) | (14)% |
| Accretion | (31,097) | (28,921) | 8% | (115,188) | (108,595) | 6% |
| Promissory note | (18,114) | (75,422) | (76)% | (104,725) | 211,077 | (150)% |
| Interest on lease obligation | (2,644) | - | 100% | (11,171) | - | 100% |
| Other finance expense | 395 | (1,014) | (139)% | (417) | (3,431) | (88)% |
| Net finance income (expense) | (44,398) | (77,327) | (43)% | (135,921) | 116,988 | 216% |
| Per boe ($) | (1.01) | (1.30) | (22)% | (0.66) | 0.63 | 205% |
Finance income includes cash interest received from the Company's short-term investments and mineral property security deposits. Finance expense includes accrued interest on Part XII.6 on flow through expenditures under the look-back rule, accretion on the Company's decommissioning liabilities, accretion and fair value adjustments on the Promissory Note (as defined herein), interest on the lease obligation and other finance expenses.
For the three months ended December 31, 2025, net finance expenses decreased to $44,398 from $77,327 in the same period of 2024 due to the changes to the book value of the promissory note partially and by a decrease in interest on short-term investments.
For the year ended December 31, 2025, net finance expense (income) decreased to $135,921 from income of ($116,988) in the same period of 2024. The changes are due primarily to the original adjustments in 2024 on the Promissory Note partially offset by the increased interest on short-term investments.
Taxes
The following table outlines the Company's estimated tax pools as at December 31, 2025:
| ($) | Year ended, December 31, | |
|---|---|---|
| 2025 | 2024 | |
| Canadian oil and gas property expense | 3,805,195 | 3,314,305 |
| Canadian development expenses | 6,007,811 | 1,189,716 |
| Canadian exploration expenses | 2,008,802 | 2,008,802 |
| Undepreciated capital cost | 914,947 | 567,868 |
| Non-capital losses (1) | 10,929,323 | 8,173,447 |
| Share issue costs | 1,120,196 | 1,547,218 |
| Income tax credits (2) | 19,592 | 19,592 |
| Estimated tax pools | 24,805,866 | 16,820,948 |
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Cash Flow from (used in) Operating Activities, Adjusted Funds Flow From (Used) in Operations and Net Loss
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Cash flow used in operating activities | (779,844) | (361,910) | 115% | (153,383) | (1,750,212) | (91)% |
| Adjusted funds flow from (used in) operations(1) | (288,773) | 281,500 | 203% | (1,033,395) | (1,021,772) | 1% |
| Net income (loss) | (4,952,844) | 396,709 | (1,348)% | (7,084,707) | (2,659,562) | 166% |
| Per share - basic | (0.02) | $ - | 100% | (0.03) | (0.02) | 50% |
| Per share - diluted | (0.02) | $ - | 100% | (0.03) | (0.02) | 50% |
(1) See Non-IFRS Measures, Non-IFRS Financial Ratios and Capital Management Measures
Cash flow used in operating activities decreased 115% for the three months ended December 31, 2025 as compared to the same period of 2024 primarily due to the decrease in the operating netback, decrease in production and the increase in G&A. Adjusted funds flow used in operations for the three months ended December 31, 2025 decreased 203% compared to the same period of 2024 primarily due to the decrease in the operating netback, decrease in production and the increase in G&A. Net loss increased 1,348% for the three months ended December 31, 2025 as compared to the same period of 2024 due primarily to the $4.18 million impairment expense recognized on the Penny CGU and by the decrease in operating netback and increased G&A.
Cash flow used in operating activities decreased 91% for the year ended December 31, 2025 as compared to the same period of 2024 primarily due to the Company posting a $1,234,834 security deposit with the Alberta Energy Regulator in 2024. Adjusted funds flow used in operations for the year ended December 31, 2025 increased 1% for the year ended December 31, 2025 as compared to the same period of 2024. Net loss increased 166% for the year ended December 31, 2025 as compared to the same period of 2024 due primarily to the $4.18 million impairment expense recognized on the Penny CGU and by the decrease in operating netback and increased G&A.
Investments
On October 13, 2023, the Company closed the sale of 90% interest of its mining claims in the Isintok property to Cascade Copper Corp. The consideration was satisfied through the issuance of 2,150,538 units of Cascade. Each unit is comprised of one Common Share and one-half of one Common Share purchase warrant, each whole warrant being exercisable for one Common Share at an exercise price of $0.15 for a period of three years. These units vested on September 28, 2024. On December 31, 2025, the investment was revalued to its fair value of $205,532, resulting in a $98,158 unrealized gain (year ended December 31, 2024: $93,212 unrealized loss) being recognized in the statement of loss. The fair value of the warrants was estimated using the Black-Scholes pricing model with the following assumptions:
| December 31, 2025 | December 31, 2024 | |
|---|---|---|
| Share price | $ 0.070 | $ 0.035 |
| Risk-free interest rate | 2.55% | 3.01% |
| Expected life (years) | 0.78 | 1.78 |
| Expected volatility | 296% | 265% |
| Fair value | $ 0.051 | $ 0.030 |
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Capital Expenditures
| ($) | Three months ended, December 31, | Year ended, December 31, | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | change | 2025 | 2024 | change | |
| Land and geological and geophysical | 54,532 | 46,547 | 17% | 940,413 | 76,382 | 1,131% |
| Drilling and completions | 32,830 | 103,722 | (68)% | 4,811,751 | 565,751 | 751% |
| Equipping and facilities | 133,199 | - | 100% | 723,716 | - | 100% |
| Other | 1,450 | 133,319 | (99)% | 461,226 | 249,030 | 85% |
| Property acquisitions | - | 60,052 | (100)% | - | 1,313,405 | (100)% |
| Total capital expenditures (1) | 222,011 | 343,640 | (35)% | 6,937,106 | 2,204,568 | 215% |
During the three months ended December 31, 2025, the Company invested a total of $222,011 on capital expenditures including $54,532 on land and geophysical, $32,830 on drilling and completions and $133,199 on equipping and facilities.
During the year ended December 31, 2025, the Company invested a total of $6,937,106 on capital expenditures including $940,413 on land and geophysical, $4,811,751 on drilling and completions, $723,716 on equipping and facilities and $459,776 on capitalized G&A. The Company drilled, completed and equipped one horizontal well in the southern Alberta deep basin in the year ended December 31, 2025.
Warrant Liability
As part of the July 15, 2022 unit offering, the Company issued 51,941,773 Common Share purchase warrants (the "2022 Warrants"). Each 2022 Warrant entitles its holder to acquire one Common Share at an exercise price of $0.11 prior to July 15, 2026. The 2022 Warrants vest and become exercisable as to one-third upon the 20-day volume weighted average trading price of the Common Shares equaling or exceeding $0.13, $0.155 and $0.18, respectively. The 2022 Warrants issued were classified as a financial liability as a result of a cashless exercise provision.
During the year ended December 31, 2025, 1,564,074 2022 Warrants were exercised for cash proceeds of $172,048 and 374,012 2022 Warrants were exercised on a cashless basis. The 2022 Warrants were fair valued on the exercise date. The total fair value, along with the proceeds received, were credited to share capital. As at December 31, 2025 there were 50,003,687 2022 Warrants outstanding of which 32,689,763 have vested and are exercisable.
The 2022 Warrants are revalued every reporting period using the Black Scholes option pricing model. For the year ended December 31, 2025, the Company recognized a remeasurement gain of $778,811 (year ended December 31, 2024: $393,476 loss). The inputs into the Black Scholes model are shown below:
| December 31, 2025 | December 31, 2024 | |
|---|---|---|
| Share price | $ 0.04 | $ 0.09 |
| Risk-free interest rate | 2.55% | 3.01% |
| Expected life (years) | 0.54 | 1.54 |
| Expected volatility (1) | 54% | 50% |
| Fair value | $ 0.0001 | $ 0.017 |
(1) Expected volatility is based on historical peer group volatility.
Share Capital
On May 28, 2024, the Company completed a brokered private placement of 26,950,000 units of the Company at a price of $0.05 per unit for aggregate gross proceeds of $1,347,500 and issued 1,000,000
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units to the agent in lieu of cash commissions. Each unit is comprised of one common share and one common share purchase warrant. Each warrant entitles holders to acquire one common share at an exercise price of $0.075 prior to the date that is 3 years from the date of issuance of the warrants. The units were recognized at an ascribed value of $368,670 to the warrants and $1,028,830 to the common shares.
In connection with the brokered private placement, the Company recorded $349,060 in share issue costs comprised of $255,381 in cash commissions and fees, $50,000 related to the issuance of 1,000,000 units to the agent as noted above, and the calculated fair value of the $43,679 associated with 1,854,000 broker warrants issued to the agent and certain selling group members.
On November 21, 2024, the Company completed a marketed offering of 111,664,805 units of the Company at a price of $0.09 for aggregate gross proceeds of $10,049,832. Each unit is comprised of one common share and one-half common share purchase warrant. Each whole warrant entitles holders to acquire one common share at an exercise price of $0.13 prior to the date that is 2 years from the date of issuance of the warrants. The units were recognized at an ascribed value of $854,320 to the warrants and $9,195,513 to the common shares.
During the year ended December 31, 2024, there were 5,254,256 Common Shares issued upon the exercise of 3,962,000 warrants and 1,292,256 broker warrants.
During the year ended December 31, 2025, there were 5,749,628 Common Shares issued upon the exercise of 5,679,228 common share purchase warrants and 70,400 broker warrants.
As at the date of this MD&A, December 31, 2025 and December 31, 2024, the following Common Shares are outstanding and/or remain issuable upon the exercise of the underlying securities.
| Number of securities | April 23, 2026 | December 31, 2025 | December 31, 2024 |
|---|---|---|---|
| Common shares outstanding | 265,563,547 | 265,563,547 | 259,813,919 |
| Warrants (1) | 159,113,044 | 169,113,044 | 174,992,730 |
| Broker warrants | 7,922,965 | 7,922,965 | 7,993,365 |
| Stock options | 8,276,667 | 14,860,000 | 20,240,000 |
| Total securities outstanding | 440,876,223 | 457,459,556 | 463,040,014 |
(1) Includes warrants classified as a warrant liability as discussed above 50,003,687 as at April 23, 2026, 50,003,687 as at December 31, 2025 and 51,941,773 as at December 31, 2024.
Warrants
The following table outlines the outstanding warrants as at December 31, 2025:
| Issued | Number outstanding | Expiry | Exercise price ($) | |
|---|---|---|---|---|
| 2022 Warrants | 15-Jul-22 | 50,003,687 | 15-Jul-26 | 0.110 |
| Acquisition Warrants (i) | 17-Mar-23 | 10,000,000 | 17-Mar-26 | 0.300 |
| 2023 Warrants (ii) | 28-Dec-23 | 28,626,955 | 28-Dec-26 | 0.075 |
| May 2024 Warrants (iii) | 28-May-24 | 24,650,000 | 28-May-27 | 0.075 |
| November 2024 Warrants (iv) | 21-Nov-24 | 55,832,402 | 21-Nov-26 | 0.130 |
(i) Acquisition Warrants – Issued on March 20, 2023, as purchase price consideration equal to $1.3 million for the acquisition of certain oil and natural gas assets in the Southern Alberta Foothills.
(ii) 2023 Warrants – Issued pursuant to a private placement for aggregate gross proceeds of approximately $1.6 million from the issuance of 31,938,299 units, each unit comprising of 1 Common Share and 1 common share purchase warrant exercisable for 1 common share at an exercise price of $0.075 prior to December 28, 2026.
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(iii) May 2024 Warrants - Issued pursuant to a private placement for aggregate gross proceeds of approximately $1.35 million from the issuance of 26,950,000 units, each unit comprising of 1 Common Share and 1 common share purchase warrant exercisable for 1 common share at an exercise price of $0.075 prior to May 28, 2027.
(iv) November 2024 Warrants: Issued pursuant to a private placement for aggregate gross proceeds of approximately $10.05 million from the issuance of 11,664,805 units, each unit comprising of 1 Common Share and one-half of a common share purchase warrant, each whole warrant being exercisable for 1 common share at an exercise price of $0.13 prior to November 21, 2026.
During the year ended December 31, 2025 there were 70,400 warrants issued upon the exercise of broker warrants and 4,012,000 warrants were exercised for 4,012,000 Common Shares for total cash proceeds of $300,900. For more details concerning the warrants, please refer to Tuktu's Annual Information Form (as defined herein), as available on the Company's SEDAR+ profile at www.sedarplus.ca.
Broker Warrants
The following table outlines the outstanding broker warrants as at December 31, 2025:
| Issued | Number outstanding | Expiry | Exercise price ($) |
|---|---|---|---|
| 28-Dec-23 | 47,744 | 28-Dec-26 | 0.05 |
| 28-May-24 | 1,842,000 | 28-May-27 | 0.05 |
| 21-Nov-24 | 6,033,221 | 21-Nov-26 | 0.09 |
Each broker warrant is exercisable for one common share and one common share purchase warrant. During the year ended December 31, 2025 there were 70,400 broker warrants exercised for 70,400 warrants and 70,400 Common Shares for total cash proceeds of $3,520. For more details concerning the broker warrants, please refer to Tuktu's Annual Information Form, as available on the Company's SEDAR+ profile at www.sedarplus.ca.
Liquidity, Capital Resources and Going Concern
Promissory note
On May 13, 2024, Tuktu agreed to a $1,234,834 promissory note from an arm's length third party. The proceeds from the promissory note were used to fund deposits with the Alberta Energy Regulator required as a condition of licence transfers for certain asset acquisitions.
The promissory note is interest free, senior secured over the Company's assets, matures on or before June 1, 2027, and requires monthly payments beginning on July 25, 2024. The monthly payments are calculated by multiplying the Company's production times a percentage ranging from 10% to 20% depending on WTI price times the realized commodity price. The Company repaid $329,466 (December 31, 2024 - $230,911) of the principal balance during the year ended December 31, 2025.
The promissory note was initially measured at fair value and then subsequently measured at amortized cost using an effective interest rate of 20%.
Liquidity
Liquidity risk is the risk that the Company will incur difficulties meeting its financial obligations as they are due. The Company's approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company's reputation. The Company prepares annual expenditure budgets, which are regularly monitored and updated as considered necessary. The information provided above (Going Concern), results in material uncertainty that may cast significant doubt on the Company's ability to continue as a going concern.
As at December 31, 2025, the Company's financial liabilities were comprised of accounts payable and accrued liabilities and promissory note which have maturities of less than one year and promissory note which has a maximum maturity of two years.
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Summary of Quarterly Results
The following table summarizes the Company's key quarterly financial and operating results for the past eight quarters.
| Q4/25 | Q3/25 | Q2/25 | Q1/25 | Q4/24 | Q3/24 | Q2/24 | Q1/24 | |
|---|---|---|---|---|---|---|---|---|
| Financial ($) | ||||||||
| Petroleum and natural gas sales | 1,610,229 | 1,694,832 | 2,438,608 | 3,274,562 | 2,438,647 | 2,513,981 | 623,872 | 528,374 |
| Cash flow from (used in) operating activities | (779,844) | (14,551) | (429,622) | 1,070,634 | (361,910) | 652,976 | (1,943,319) | (97,959) |
| Net income (loss) | (4,952,844) | (1,331,016) | (71,370) | (729,477) | 396,709 | (1,886,337) | (992,419) | (177,515) |
| Per share - basic | (0.02) | (0.01) | 0.00 | 0.00 | 0.00 | (0.01) | (0.01) | 0.00 |
| Per share - diluted | (0.02) | (0.01) | 0.00 | 0.00 | 0.00 | (0.01) | (0.01) | 0.00 |
| Total capital expenditures (1) | 222,011 | 154,216 | 787,477 | 5,773,402 | 343,640 | 596,880 | 1,264,048 | - |
| Weighted average shares outstanding (thousands) | ||||||||
| Basic | 265,564 | 265,564 | 265,506 | 262,931 | 196,738 | 143,038 | 125,388 | 114,945 |
| Diluted | 265,564 | 265,564 | 265,506 | 262,931 | 259,181 | 143,038 | 125,388 | 114,945 |
| Shares outstanding, end of period (thousands) | ||||||||
| Basic | 265,564 | 265,564 | 265,564 | 265,460 | 259,814 | 144,707 | 142,895 | 114,945 |
| Diluted | 265,564 | 265,564 | 265,564 | 265,460 | 325,575 | 144,707 | 142,895 | 114,945 |
| Operational | ||||||||
| Average daily production: | ||||||||
| Crude oil (bbls/d) | 187 | 215 | 298 | 358 | 271 | 305 | 43 | 2 |
| Natural gas (mcf/d) | 1,742 | 1,408 | 1,943 | 2,081 | 2,236 | 1,819 | 2,156 | 2,198 |
| Total (boe/d) | 477 | 450 | 622 | 705 | 644 | 608 | 402 | 368 |
(1) See Non-IFRS Measures, Non-IFRS Financial Ratios and Capital Management Measures
The Company completed an acquisition of oil assets in the second quarter of 2024 with production to the account of the Company commencing on May 27, 2024. The Company completed a successful recompletion on an oil well in the third quarter of 2024 which increased petroleum and natural gas sales for the period. Finally, the Company purchased land and drilled, completed and equipped a horizontal dry well in southern Alberta in the first half of 2025.
Cash flow from (used in) operating activities increased in the second quarter of 2024 due to the Company posting a $1,234,834 security deposit with the Alberta Energy Regulator. Cash flow from (used in) operating activities increased in the fourth quarter of 2025 due to declining production, lower realized oil prices and higher operating costs.
Net income fluctuations have been primarily due to the quarterly remeasurement gains and losses on the warrant liability which is caused by stock price and interest rate variability. In the fourth quarter of 2025 a $4,180,000 impairment expense was recognized as a result of the dry horizontal well drilled in southern Alberta during the first half of 2025.
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Selected Annual Information
The following table summarizes key annual financial and operating information over the three most recently completed financial years.
| 2025 | 2024 | 2023 | |
|---|---|---|---|
| Financial ($) | |||
| Petroleum and natural gas sales | 9,018,231 | 6,104,874 | 1,590,787 |
| Cash flow used in operating activities | (153,383) | (1,750,212) | (1,015,545) |
| Net income (loss) | (7,084,707) | (2,659,562) | 1,193,531 |
| Per share - basic and diluted | (0.03) | (0.02) | 0.01 |
| Total capital expenditures | 6,937,106 | 2,204,568 | 2,072,990 |
| Total assets | 14,912,569 | 22,637,972 | 9,387,265 |
| Total liabilities | 9,496,022 | 10,954,941 | 5,643,883 |
| Shareholders' equity (deficiency) | 5,416,547 | 11,683,031 | 3,743,382 |
| Weighted average shares outstanding (thousands) | |||
| Basic and diluted | 264,814 | 145,163 | 81,302 |
| Shares outstanding, end of period (thousands) | |||
| Basic and diluted | 264,814 | 259,814 | 114,945 |
| Operational | |||
| Average daily production: | |||
| Crude oil (bbls/d) | 264 | 156 | 1 |
| Natural gas (mcf/d) | 1,792 | 2,102 | 1,686 |
| Total (boe/d) | 563 | 506 | 282 |
In 2023 and 2024, Tuktu was successful in completing acquisitions and capital projects to grow production and sales. The total capital expenditures have been funded by the issuance of securities through private placements in 2023 and 2024 as well as a marketed prospectus offering in 2024. Net income fluctuations have been primarily due to the remeasurement gains and losses on the warrant liability which is caused by stock price and interest rate variability and a $4,180,000 impairment that was recognized in 2025.
Off-Balance Sheet Arrangements
Tuktu has not entered into any material off-balance sheet arrangements.
Non-IFRS Measures, Non-IFRS Financial Ratios and Capital Management Measures
This MD&A contains certain financial measures and ratios, as described below, which do not have standardized meanings prescribed by IFRS Accounting Standards. As these non-IFRS and other financial measures are commonly used in the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used.
The non-IFRS and other financial measures used in this MD&A are used by the Company as key measures of financial performance and are not intended to represent operating profits, nor should they be viewed as an alternative to cash provided by operating activities, net income or other measures of financial performance calculated in accordance with IFRS Accounting Standards. Management believes that the presentation of these non-IFRS, capital management and other financial measures provides useful
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information to shareholders and investors in understanding and evaluating the Company's ongoing operating performance.
Adjusted Funds Flow from (used in) Operations
Adjusted Funds flow from (used in) operations is calculated by taking cash flow used in operating activities and adding back changes in non-cash working capital, decommissioning costs incurred and transaction costs. Management considers adjusted funds flow used in operations to be a key measure to assess the performance of the Company's oil and natural gas properties and the Company's ability to fund future capital investment. Adjusted funds flow used in operations is an indicator of operating performance as it varies in response to production levels and management of costs. Changes in non-cash working capital, decommissioning costs incurred and transaction costs vary from period to period and management believes that excluding the impact of these provides a useful measure of the Company's ability to generate the funds necessary to manage the capital needs of the Company.
The Company reconciles adjusted funds flow from (used in) operations to cash flow from (used in) operating activities, which is the most directly comparable measure calculated in accordance with IFRS as follows:
| ($) | Three months ended, December 31, | Year ended, December 31, | ||
|---|---|---|---|---|
| 2025 | 2024 | 2025 | 2024 | |
| Cash flow used in operating activities | (779,844) | (361,910) | (153,383) | (1,750,212) |
| Changes in non-cash working capital | 491,071 | 643,410 | (880,012) | 728,440 |
| Adjusted funds flow from (used in) operations | (288,773) | 281,500 | (1,033,395) | (1,021,772) |
Operating netbacks
Operating netback is total petroleum and natural gas revenues less royalties, operating expenses and transportation expenses. These metrics can also be calculated on a per boe basis, which results in them being considered a non-IFRS ratio. Management considers operating netback as an important measure to evaluate the Company's operational performance, as it demonstrates field level profitability relative to current commodity prices.
Adjusted working capital
Adjusted working capital is calculated by taking working capital (current assets less current liabilities) and adding back the warrant liability and current portion of decommissioning obligations. Management believes that adjusted working capital assists management and investors in assessing Tuktu's short-term liquidity. The following table provides a reconciliation of working capital as determined with IFRS to adjusted working capital:
| ($) | December 31, 2025 | December 31, 2024 |
|---|---|---|
| Working capital | 403,970 | 7,810,819 |
| Warrant liability | 2,250 | 881,399 |
| Current portion of decommissioning obligations | 447,622 | 138,874 |
| Adjusted working capital | 853,842 | 8,831,092 |
Capital expenditures
Management uses the term "capital expenditures" as a measure of capital investment in exploration and production activity, as well as property acquisitions and dispositions. The most directly comparable IFRS measure for total capital expenditures is cash flow used in investing activities. Capital expenditures represent capital expenditures – exploration and evaluation, capital expenditures – property, plant and equipment, property acquisition and proceeds on property disposition in the Company's Interim Financial Statements. The following table provides a reconciliation of cash flow used in investing activities to capital expenditures.
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| ($) | Three months ended, December 31, | Year ended, December 31, | ||
|---|---|---|---|---|
| 2025 | 2024 | 2025 | 2024 | |
| Cash flow used in investing activities | (257,368) | (189,622) | (6,919,656) | (720,600) |
| Interest earned on mineral property security deposits | 28 | 73 | 193 | 257 |
| Changes in non-cash working capital | 35,329 | (154,091) | (17,643) | (1,484,225) |
| Total capital expenditures | (222,011) | (343,640) | (6,937,106) | (2,204,568) |
Supplementary Financial Measures
Per boe disclosure for petroleum and natural gas sales, royalties, operating expenses, transportation expenses, G&A expenses, share-based compensation, finance income and expenses, and depletion and depreciation are supplementary measures that are calculated by dividing each of these respective IFRS measures by the Company's total production volumes for the period.
Average realized prices for crude oil and natural gas are supplementary financial measures calculated by dividing each of these components of petroleum and natural gas sales by their respective production volumes for the period.
Royalties as a percentage of petroleum and natural gas revenues is a supplementary financial measure calculated by dividing royalties by petroleum and natural gas sales.
Advisories
BOE Presentation
This MD&A contains various references to the abbreviation "boe", which refers to barrel of oil equivalent, and "boe/d", which refers to barrels of oil equivalent per day. Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used in the calculation of boe amounts in this MD&A. The boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
NI 51-101 References
Throughout this MD&A, "crude oil" or "oil" refers to light and medium crude oil product types as defined by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). References to "gas" relates to natural gas.
Abbreviations
The Company uses the below industry terms, abbreviations and acronyms in the MD&A:
AECO - Alberta Energy Company "C" Meter Station of the NOVA Pipeline System, the Canadian benchmark price for natural gas
bbl - barrels
bbls/d - barrels per day
boe - barrels of oil equivalent
boe/d - barrels of oil equivalent per day
mcf - thousand cubic feet
mcf/d - thousand cubic feet per day
mmcf/d - one million cubic feet per day
GJ - gigajoules
WTI - West Texas Intermediate
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Critical Accounting Estimates and Judgements
The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Estimates are more difficult to determine, and the range of potential outcomes can be wider, in periods of higher volatility and uncertainty. The impacts of geopolitical events such as the tariffs between Canada and the United States, regional conflicts, especially in oil producing areas, can materially impact energy markets, interest and inflation rates and supply chains resulting in higher levels of volatility and uncertainty. Actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis and are based on managements' experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future years affected.
In the process of applying the Company's accounting policies, management has made the following judgments, apart from those involving estimates, which may have the most significant effect on the amounts recognized in the financial statements.
(i) Business combinations:
Management's determination of whether a transaction constitutes a business combination or asset acquisition is determined based on the criteria in IFRS 3 Business Combinations ("IFRS 3"). Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant and equipment ("PP&E") and exploration and evaluation ("E&E") assets acquired generally require the most judgement and include estimates of proved and probable oil and natural gas reserves acquired, forecast benchmark commodity prices, discount rates, future costs and the assessment of recent comparable transactions. Changes in any of these assumptions or estimates used in determining the fair values of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill or bargain purchase price.
(ii) Cash generating units:
A cash generating unit ("CGU") is defined as the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups thereof. The Company allocates costs to a CGU based on geographic location, shared infrastructure, and common geological and geophysical characteristics.
(iii) Reserves estimates:
The Company uses estimated proved and probable oil and natural gas reserves to deplete its oil and natural gas assets included in property, plant and equipment, to assess for indicators of impairment on the Company's CGU and if any such indicators exist, to perform an impairment test to estimate the recoverable amount of the CGU. Estimates of proved and probable oil and natural gas reserves are based upon a number of significant assumptions, such as forecasted production volumes, forecasted oil and natural gas commodity prices, forecasted operating costs, forecasted royalty costs and forecasted future development costs. The Company engaged independent third-party reserve evaluators to evaluate the Company's estimates of proved and probable oil and natural gas reserves as at December 31, 2025. Reserve estimates are made annually based on actual volumes produced, the results from capital expenditure programs, revisions to previous estimates, new discoveries and acquisitions and dispositions made during the year.
Proved oil and natural gas reserves are those forecasted quantities of oil and natural gas determined to be economically recoverable under existing economic and operating conditions with a high degree of certainty, of at least 90 percent, that those quantities will be equalled or exceeded. Probable oil and natural gas reserves are those forecasted quantities of oil and natural gas determined to be economically recoverable under existing economic and operating conditions with a moderate degree
- 19 -
of certainty, of at least 50 percent, that those quantities will be equalled or exceeded. The Company reports production and reserve quantities in accordance with Canadian practices and specifically in accordance with Standards of Disclosures for Oil and Gas Activities ("NI 51-101").
The estimate of proved plus probable reserves is an essential part of the depletion calculation and the indicators of impairment or impairment reversal assessment and if necessary, the related impairment test and hence the recorded amount of oil and natural gas assets. The estimate of the cash flows associated with proved and probable reserves are a key component in the indicators of impairment or impairment reversal assessment and if necessary, the related impairment test for property, plant and equipment and the measurement of the deferred income tax asset.
The Company cautions users of this information that the process of estimating oil and natural gas reserves is subject uncertainty. The reserves are based on current and forecast economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include commodity prices, new technology, changing economic conditions, future reservoir performance and forecast development activity.
(iv) Impairment of oil and natural gas assets:
Judgements are required to assess when indicators of impairment or impairment reversal exist and impairment testing is required. In determining the estimated recoverable amount of assets or CGUs, in the absence of quoted market prices, impairment tests are based on the estimate of proved and probable oil and natural gas reserves using a number of significant assumptions, such as forecasted oil and natural gas commodity prices, forecasted production volumes, forecasted operating costs, forecasted royalty costs, forecasted future development costs and discount rates.
(v) Exploration and evaluation assets:
The application of the Company's accounting policy for exploration and evaluation assets requires management to make certain judgements about future events and circumstances as to whether economic quantities of proved and probable petroleum and natural gas reserves have been found in assessing economic and technical feasibility.
(vi) Decommissioning obligations:
The Company estimates future retirement and remediation of the Company's assets which in most cases, occurs many years into the future. This requires assumptions regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating costs, future removal technologies in determining the removal cost and liability-specific discount rates to determine the present value of these cash flows.
(vii) Income taxes:
The Company recognizes deferred income tax assets to the extent that it is probable that taxable profit will be available to allow the benefit of that deferred income tax asset to be utilized. Assessing the recoverability of deferred income tax assets requires the Company to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Company to realize the deferred income tax assets recorded at the reporting date could be impacted. Additionally, future changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods.
(viii) Share-based compensation and warrant liabilities:
In determining the estimated fair value of stock options, the Company makes assumptions regarding share price volatility, risk free rate and forfeiture rate.
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In determining the estimated fair value of the warrant liability at the end of each reporting period requires management judgement to determine significant assumptions to the valuation model, including expected life and volatility rate.
Changes in Accounting Policy
There were no changes that had a material effect on the reported income of net assets of the Company.
Standards Issued but not yet Effective
IFRS 18 “Presentation and disclosure in financial statements” has been issued which will replace IAS 1 “Presentation of financial statements”. The new standard established a revised structure for the statements of comprehensive profit with the intention to improve comparability across entities. IFRS 18 is effective for annual periods beginning on or after January 1, 2027 and will be applied retroactively. The Company is currently evaluating the impact of adopting IFRS 18 on the financial statements.
The International Accounting Standards Board issued amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures with the intention to clarify the date of recognition and derecognition of some financial assets and liabilities. The amendments are effective January 1, 2026 with early adoption permitted. The Company is currently evaluating the impact of this standard on the financial statements.
Risks and Uncertainties
The Company’s business is inherently risky and there is no assurance that oil and natural gas reserves will be discovered and economically produced. Financial risks associated with the oil and natural gas industry include fluctuations in commodity prices, interest rates, currency exchange rates, the effects of inflation and the ability to access debt and/or equity financing. Land reclamation requirements on the Company’s properties may be burdensome and the Company must allocate financial resources to reclamation activities that may otherwise be spent on exploration and development programs. The following information is a summary only of certain risk factors relating to the Company and should be read in conjunction with Tuktu’s annual information form for the year ended December 31, 2025 (the “Annual Information Form”), which can be found on the Company’s SEDAR+ profile at www.sedarplus.ca. The risks set out below are not an exhaustive list, nor should be taken as a complete summary or description of all of the risks associated with the Company’s business and the oil and natural gas business generally.
Credit risk
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations that arise principally from the Company’s accounts receivable from oil and natural gas marketers and joint operators in the oil and natural gas industry. Receivables from oil and natural gas marketers are normally collected on the 25th day of the month following production.
The Company mitigates credit risk by maintaining relationships with large, established, reputable and creditworthy purchasers. The Company attempts to mitigate risk from joint venture receivables by obtaining partner approval of significant capital and operating expenditures prior to expenditure. Joint venture receivables are from partners in the oil and natural gas industry that are subject to the risks and conditions of the industry. Significant changes in industry conditions and risks that negatively impact partners’ ability to generate cash flow will increase the risk of not collecting receivables. The Company has the ability to withhold production from joint interest partners in the event of non-payment.
As at December 31, 2025, the Company’s accounts receivable was $613,426 (December 31, 2024: $1,303,063) of which $558,687 (December 31, 2024: $1,221,413) is current and $54,739 (December 31, 2024: $81,650) is past 90 days due.
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Liquidity risk
Liquidity risk is the risk that the Company will incur difficulties meeting its financial obligations as they are due. The Company's approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company's reputation. The Company prepares annual expenditure budgets, which are regularly monitored and updated as considered necessary. The information provided in the "Going Concern" section above, results in material uncertainty that may cast significant doubt on the Company's ability to continue as a going concern.
As at December 31, 2025, the Company's financial liabilities were comprised of accounts payable and accrued liabilities and promissory note which all have a maturity of less than one year and promissory note which has a maximum maturity of two years.
Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate risk primarily through its variable interest rate on its cash and cash equivalents as it has not entered into any interest rate hedging contracts. For the year ended December 31, 2025 and 2024, if interest rates had been 1% higher with all other variables held constant, the change in net loss would have been insignificant.
Equity price risk
Equity price risk refers to the risk that the fair value of the investments will fluctuate due to changes in equity markets. Equity price risk arises from the realizable value of the investments that the Company holds which are subject to variable equity market prices which on disposition gives rise to a cash flow equity price risk. The Company will assume full risk in respect of equity price fluctuations.
Political Uncertainty
The Company's results can be adversely impacted by political, legal, or regulatory developments in Canada and elsewhere that affect local operations and local and international markets. Changes in government, government policy or regulations, changes in law or interpretation of settled law, third-party opposition to industrial activity generally or projects specifically and duration of regulatory reviews could impact Tuktu's existing operations and planned projects. This includes actions by regulators or other political actors to delay or deny necessary licenses and permits for the Company's activities or restrict the operation of third-party infrastructure that the Company relies on. Additionally, changes in environmental regulations, assessment processes or other laws, and increasing and expanding stakeholder consultation (including Indigenous stakeholders), may increase the cost of compliance or reduce or delay available business opportunities and adversely impact Tuktu's results. Other government and political factors that could adversely affect the Company's financial results include increased taxes or government royalty rates and changes in trade policies and agreements. Further, the adoption of regulations mandating efficiency standards, and the use of alternative fuels or uncompetitive fuel components could affect the Company's operations. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources, and the success of these initiatives may decrease demand for the Company's products.
The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, the imposition of tariffs, embargoes or export restrictions on the Company's products. Since February 2025, the U.S. administration has announced, suspended, and reimposed various tariffs on Canadian imports, including tariffs on Canadian energy imports. On February 20, 2026, the U.S. Supreme Court held that the Trump administration lacked legal authority to impose certain tariffs under the International Emergency Economic Powers Act. In response, the administration imposed a temporary global tariff under the Trade Act of 1974 and indicated its intention to pursue alternative trade measures. The Canada-United States-
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Mexico Agreement is scheduled for comprehensive joint review in July 2026, which may result in modifications to the trade framework governing cross-border energy commerce. The imposition, continuation, or expansion of tariffs on Canadian energy exports could reduce the realized prices for the Company's production, increase costs for imported goods and services used in the Company's operations, and disrupt North American commodity markets. Retaliatory trade measures by Canada could further increase costs and uncertainty.
In addition to the potential impact on energy, tax and climate policy resulting from the Canadian federal election held in April 2025, and any resulting changes in government policy direction, could create uncertainty for the Canadian energy industry. The precise duration and extent of the adverse impacts of the current macroeconomic and global economic activity on the Company's operations remains uncertain at this time.
Forward Looking Statements
This MD&A contains statements with words such as "anticipate", "believe", "continue", "expect", "plan", "intend", "estimate", "propose", "project", "budget", "forecast", "guidance", "objective", "outlook", "targeting", "could", "potential", "strategy", "should", "will", "may" or similar words (including grammatical variations or negatives thereof) suggesting future outcomes or statements regarding an outlook. In addition, the statements contained herein relating to "reserves" and "resources" are by their nature forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves or resources described can be profitably produced in the future. The recovery, reserves and resources estimates provided herein are internal estimates only and there is no guarantee that the estimated reserves or resources will be recovered. Therefore, actual results may differ materially from those anticipated in the forward-looking statements. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
Assumptions
Forward-looking statements or information are based on a number of factors and assumptions which have been used in developing such statements and information, but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this MD&A, assumptions have been made regarding, among other things: the accuracy of geological and geophysical data and interpretation of that data; estimated decline rates; the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the Company to operate in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; the extent of the Company's liabilities; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing of and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate transportation for products; future oil and natural gas prices; foreign currency exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; government regulations, law, tariffs, and other restrictive trade measures; the ability of the Company to successfully market its oil and natural gas products; and future and prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.
Risks and Uncertainties
Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These
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risks and uncertainties which may cause actual results to differ materially from the forward-looking statements or information include, among other things: the ability of management to execute its business plan; general economic and business conditions; risks associated with the oil and natural gas industry in general (e.g. operational risks in exploring for, developing and producing crude oil and natural gas; market demand; changes to supply and demand for oil and natural gas; uncertainty of reserves estimates; uncertainty of estimates and projections relating to production, costs and expenses, including increased operating and capital costs due to inflationary pressures); the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertainties involving geology of oil and natural gas deposits; the ability of the Company to add production and reserves through acquisition, development and exploration activities; the Company's ability to enter into or renew leases; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; fluctuations and uncertainty with respect to foreign currency exchange rates and interest rates; stock market and financial system volatility; determinations by the Organization of Petroleum Exporting Countries and other countries (collectively referred to as OPEC+) regarding production levels, and the risk of an extended period of low oil and natural gas prices; the potential impact on energy, tax, and climate policy resulting from the Canadian federal election held in April 2025, and any resulting changes in government policy and direction; changes in industry regulations and legislation (including, but not limited to, tax laws, royalties, and environmental regulations); the imposition or expansion of tariffs imposed by domestic and foreign governments or the imposition of other restrictive trade measures, retaliatory or countermeasures implemented by such governments, including the introduction of regulatory barriers to trade and the potential effect on the demand and/or market price for the Company's products and/or otherwise adversely affects the Company, including risks arising from the scheduled review of the Canada-United States-Mexico Agreement in July 2026; the risk that the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; the risk that tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension, the Canadian oil and natural gas industry and the Company; risks inherent in the Company's marketing operations, including credit risk; uncertainty in amounts and timing of royalty payments; health, safety and environmental risks; effects of inclement and severe weather or events, including fire, drought, flooding and extreme cold temperatures; risks associated with existing and potential future law suits and regulatory actions against the Company; uncertainties as to the availability and cost of financing; financial risks affecting the value of the Company's investments; interest rates and commodity prices; changes in the political landscape both domestically and abroad, political uncertainty, geopolitical conflicts, hostilities, civil insurrections and wars, foreign exchange or interest rates; increased operating and capital costs due to inflationary pressures (actual and anticipated); the impact of Russia's military actions in Ukraine; the broader Israeli-Hamas conflict, including escalations between Israel and Iran; ongoing Houthi attacks on Red Sea shipping; the collapse of the Syrian Assad regime and uncertainty regarding the transitional government; and the impact of oil differentials on the Company's financial position. Since February 2025, the U.S. administration has announced, suspended, and reimposed various tariffs on Canadian imports, including tariffs on Canadian energy imports. On February 20, 2026, the U.S. Supreme Court held that the Trump administration lacked legal authority to impose certain tariffs under the International Emergency Economic Powers Act. In response, the administration imposed a temporary global tariff under the Trade Act of 1974 and indicated its intention to pursue alternative trade measures. The imposition, continuation, or expansion of tariffs on Canadian energy exports could reduce the realized prices for the Company's production, increase costs for imported goods and services used in the Company's operations, and disrupt North American commodity markets. As Canada-U.S. trade relations continue to evolve, the potential for further tariff-related conflicts could introduce additional volatility and risks to the Company's operations. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. The foregoing list is not exhaustive. Please refer to the Annual Information Form for discussion of additional risk factors relating to Tuktu, which can be accessed on the Company's SEDAR+ profile at www.sedarplus.ca or on the Company's website at www.tukturesources.com.
This disclosure contains certain forward-looking statements that involve substantial known and unknown risks and uncertainties, certain of which are beyond the Company's control. These include, but are not limited to: the impact of general global economic conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; competition; the lack of availability of qualified personnel or management; the lack of availability of or access to services; fluctuations in foreign exchange rates, interest rates or commodity prices; the results of
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exploration and development drilling related activities; imprecision in reserve estimates; market volatility; changes to market valuations; and obtaining required approvals from regulatory authorities.
These known and unknown risks and uncertainties may cause actual financial and operating results, performance, levels of activity and achievements to differ materially from those expressed in, or implied by, such forward-looking statements. Accordingly, there is no assurance that the expectations conveyed by the forward-looking statements will prove to be correct. All subsequent forward-looking statements, whether written by or orally attributable to the Company or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. The Company undertakes no obligation to publicly update or revise any forward-looking statements.
Corporate Information
As of the date of this report, the Company had the following directors and officers:
Jeremy Hodder President and Chief Executive Officer
Craig Wall Vice President, Finance and Chief Financial Officer
Sony Gill Corporate Secretary
Robert Dales Director
William Guinan Director
Natalie Sweet Director
Kathleen Dixon Director
Robert Yurchevich Director